Apparatus and methods are known for single-trip completions of deviated wellbores, such as horizontal wellbores. To date, unlike the drilling industry which commonly utilizes intelligent apparatus for drilling wellbores, particularly horizontal or deviated wellbores, the fracturing industry has relied largely on mechanically-actuated apparatus to perform at least a majority of the operations required to complete a wellbore. This is particularly the case with coiled-tubing deployed bottom hole assemblies (BHA's), largely due to the difficulty in providing sufficient, reliable electrical signals and power from surface to the BHA and from the BHA to surface.
It is known to deploy BHA's for completion operations using jointed tubular, wireline or cable and using coiled tubing (CT). Further it is known to use wireline deployed within an interior of CT to actuate conventional select-fire perforation charges and to transmit signals associated with casing-collar locators used in depth measurement such as taught in U.S. Pat. No. 7,059,407.
As new resources are being developed, the industry has an interest in fracturing operations in horizontal wells, such as wellbores which may have minimal vertical portions and very long horizontal wellbores. Use of coiled tubing to deploy conventional BHA's, particularly using small diameter CT, is problematic in such wellbores as one cannot easily run in CT to the toe of the very long horizontal wellbores.
Generally, a conventional BHA for use with CT and used for completion of new wellbores incorporates a jetting sub for perforation of casing or the wellbore wall and a single sealing element, such as a resettable bridge plug, for sealing the wellbore below the jetted perforations for treating the formation therethrough. The treatment fluid, such as a fracturing fluid, is then pumped through the annulus between the casing and the CT, or through the bore of the CT, or both.
In the case of previously perforated wellbores, a separate BHA is used which incorporates two spaced-apart sealing elements, such as packer cups or mechanically-set or hydraulically-set packers, which straddle the existing perforations. Treatment fluid is delivered through the bore of the CT to be delivered to the perforations isolated between the sealing elements.
Prior art tools used for performing fracturing operations at multiple zones in a formation have used wireline deployed, electrically-actuated bridge plugs which are pumped into the wellbore. The known pump-down bridge plugs have a single, fixed diameter being slightly smaller than the wellbore for deployment into the wellbore and require a valve at a toe of the wellbore to get rid of fluid used to pump the bridge plug into place. As wireline is comparatively weak and cannot pull more than about 2500 lbs at surface, and much less at depth, the wireline cannot be reliably used to release or to pull the bridge plugs to surface. Thus, multiple bridge plugs must be used and left in the wellbore to be drilled out later, at considerable expense. After the bridge plug has been set, the casing is perforated with perforating guns located above the bridge plug. The bridge plug and the perforating guns are often deployed together so that both operations, isolating and perforating, can be done in the same wireline run. When the perforations have been shot, the wireline is pulled out of the hole and the fracture fluid is pumped through the casing. Once the fracture is completed, the steps of setting the bridge plug and perforating followed by pumping the frac are repeated for sequential uphole intervals until the fracturing job on the wellbore is complete. This method is commonly referred to as “plug and perf”. Following fracturing of all of the zones, the bridge plugs are drilled out.
Conventional perforating guns are also incorporated into BHA's which are used for completion of new wellbores. Typically, conventional perforating guns utilize detonation cord for connecting between and actuating a plurality of spaced apart shaped charges therein which results in a very long perforating gun. Generally, in embodiments of conventional operations, it is desirable to perforate as many zones as possible in a single run. In order to maximize the number zones which can be perforated, very long conventional select-fire perforating guns are required. The length of the perforating guns impacts conventional operations, requiring very tall cranes and other support apparatus to hold and inject the very long gun assemblies and BHA into very tall lubricators, often exceeding about 30 meters. In many cases, the number of zones which can be perforated in a single trip is limited to permit a reasonable length for the BHA and lubrication apparatus.
In many cases, at least two separate BHA's are required when operators are fracturing both new wellbores and previously perforated wellbore. In the case of new wellbores, once perforations are formed or a sliding sleeve is actuated to open pre-existing ports in the casing, a single isolation apparatus is used to seal the annulus therebelow to isolate the newly-formed perforations to be treated from the previous perforations formed therebelow. Treatment fluid can be delivered to the formation through the annulus between the casing and the ct, or, in some cases, through the CT, or through both at the same time. In the case of old wellbores having previously formed perforations or opened ports therein, particularly where sleeves cannot be actuated to close, two spaced apart isolation apparatus are required to straddle the perforations or ports to be treated and treatment fluid is delivered through the tubing string to the isolated perforations or ports therebetween.
As will be appreciated by those of skill in the art, monitoring pressure downhole during fracturing operations is indicative of how the formation is reacting to the fracturing operation and may also be indicative of the integrity of the isolation apparatus and the formation between adjacent zones. Generally, downhole pressures are not monitored directly, but instead are calculated from parameters measurable at surface. For example, when treatment fluid is delivered to the formation through one or the other of the annulus or the tubing string, the other can act as a “dead leg”. For example, when the treatment fluid is delivered through the annulus, a minimal, constant amount of a deadhead fluid is delivered through the tubing string to act as the “dead leg”, maintaining pressure within the tubing string. The pressure required to maintain the constant fluid delivery is monitored from surface and can be used for calculating fracture extension pressure and formation breakdown pressure, as well as fracture closure pressure.
It is known to use microseismic monitoring where operators wish to monitor fracture growth and development, either in real time or retroactively to optimize subsequent fracturing operations. Prior art systems typically require a conveniently located offset observation wellbore and wireline truck to deploy an array of sensors in the observation wellbore, which can monitor the fracturing operation. Alternatively, an extensive microseismic surface array may be used. Both systems benefit from use of a multi-string shot tool (MSST) for creating known microseismic events as a result of detonation of string shots therewith at known locations in the wellbore to aid in developing more accurate velocity profiles and calibrating the sensors.
Clearly, there is great interest in the industry to develop tools which enable completion of multiple zones in a single trip while optimizing the apparatus required and reducing cost and operational man hours. There is a further interest in apparatus and methods for improving the ability to accurately monitor fracture growth and placement for optimizing fracturing operations. Further, there is interest in developing tools having diagnostic capabilities that would greatly improve the reliability of the tools and processes used.